This invention is related to the measurement of flow rates and component fractions of individual phases of a composite fluid. More particularly, the invention is directed toward apparatus and methods for determining the volumetric flow rate or mass flow of one or more phases of a fluid by measuring the activity of one or more specific radioactive isotopes affected by a specific phase of the flowing fluid stream.
Fluid flow meters are used in many areas of industry and commerce. Various nuclear, acoustic, electromagnetic, mechanical and electronic techniques have been used to measure linear flow velocity, volumetric flow rates, and mass flow of fluids containing one, two, or more components or "phases" such as water, natural gas and crude oil. The multiple phase, or "multi-phase" flow meters are especially important to the petroleum industry.
Orifice type flow meters are widely used to measure single phase flow, such as fluids comprising 100% liquid, and are used extensively for 100% gas in the natural gas industry. In orifice flow meters, fluid is forced to flow through an orifice in a plate within the flow conduit, creating a pressure drop across the plate. Orifice flow meters are relatively inexpensive to fabricate and to maintain, and are reliable in many types of field operations. In addition, the physical size of most orifice devices is relatively small. Measures of the differential pressure across the plate, along with flow stream pressure and temperature measurements, are used to compute flow rate using equations well known in the art.
Orifice plates are virtually impossible to use in multi-phase stream flow because of the effect the concentric restriction has on "damming" the liquid flow in front of the plate, and the resulting pooling of liquids downstream of the plate. Little success has been indicated in tests, even of high gas fraction multi-phase flow where the gas and vapors constitute more than 98% of the fluids. Any amount of free liquids corrupts generation of a representative differential pressure, and therefore corrupts the resulting flow calculations from these differential pressure measurements. Liquids change the effective pipe diameter, the orifice diameter, the beta ratio of the orifice meter, the pipe roughness and the shape of the vena contracta, and thus the entire flow equation at spazemotic intervals depending on the relative velocities of the phases. At present, there is no "state-of-the art" software or flow equation that can adequately represent multi-phase flow through an orifice plate, even utilizing any existing type of fractional flow determination device.
The venturi, another inferred flow measurement device utilizing differential pressure, can be used to measure multiphase flow only if an independent measure of the ratio of the phases is made. Furthermore, accurate measures of volumetric flow rates of each phase can be obtained if the linear flow velocities of the phases are the same, or the relative "slippage" of the linear phase flows can be determined, or all phases are forced to flow at the same linear flow velocity at the position which the phase ratio and differential pressure measurements are made. All existing multi-phase flow technology that utilizes an inferred flow measurement from differential pressure is done with some special designs of venturi tubes. All existing multi-phase flow technology that utilizes an inferred flow measurement from differential pressure is done with some special designs of venturi tubes. Virtually all comments made concerning orifice measurements are also applicable to venturi flow measurement.
Positive displacement type flow meters force fluid to flow through a positive volumetric apparatus, and the flow rate of the fluid is determined from the rate of revolution of the meter displacer device. Positive displacement type meters may be used in multiphase flow meters. As with venturi flow meters, independent phase ratio measurements must be made using a variety of technologies. The positive displacement flow meter forces all phases of the flow to move through the meter at the same velocity. Those velocities can change quite readily in slug flow, but both the gas and the liquids are at the same flow rate (velocity) at the moment in time as they pass through the meter. The relative ratio of the liquids and the gas to liquids must be obtained at close to the same time in order to obtain the desired multi-phase flow measurements. Positive displacement meters are more complex than venturi flow meters, are more costly to manufacture and to maintain, and are in general larger in physical size.
Tracers have also been used in prior art multi-phase flow measurements. Various materials, usually referred to as "tracers" or "tags", are introduced into a flowing stream comprising one or more phases. Tracers can be radioactive or stable elements or compounds. Preferably, a specific tracer binds to only a specific phase of the composite flow. Detectors, which respond to tracer concentration, are placed downstream from the point of tracer injection. Measured tracer concentration is then related to the flow rate of the phase which the tracer binds. Usually relatively large amounts of tracer material must be injected into the flowing stream to obtain statistically significant measurements. This is especially a problem if radioactive tracers are employed, since the fluid is essentially contaminated with radioactive material. In addition, and as is the case with venturi flow meters, numerous assumptions must be made and/or numerous additional independent measurements must be made in order to convert measured tracer concentration into multi-phase volume or mass flow measurements.
Separators are widely used in multiple-phase flow measurements. As an example, in the petroleum industry, it is of interest to measure volumetric flow rates of the three fluids produced, namely oil, gas and water. Gravity separators are widely used to separate these three components of differing density, and then the separated components are each drawn from the separator and single phase flow measurements are made on each separated components. Characteristically, separators are physically large, are expensive to construct, require a relatively long period of time for the multiple phases to separate by means of the force of gravity, and require a separate flow meter for each separated phase. In addition, separators have an inherent error because of entrained or solution gas, and carry over from one phase to another. As examples, some water can remain within an oil phase, and gas can remain dissolved within the liquid phases. The test separator is capable of giving definitive answers to three phase flow measurements only if all of the various factors of the three meters measuring the various flows are considered. Such factors include the dump rates for the liquids being five to ten times the average flow rate, the entrained gas in both the water and oil phases expanding as the pressure is lowered going through the separator and meters and thereby over-registering the volume of liquids, liquids being carried through the gas meter by the higher gas velocity and insufficient demisting, and changes in the liquid levels due to slugging which results in insufficient separation. These factors are more often than not disregarded and result in a large percentage of test separator testing on producing wells which overstate the volumes from a nominal 10% to values exceeding 100% when compared to sales volumes. In addition, the test separator requires massive, heavy, costly equipment, significant size and time for complete phase separation, and is certainly not applicable for real time, pipeline measurements where there often are sudden changes in the flow phase composition and the flow regime.
Various two and three phase "in-line" multi-phase flow meters have been developed, especially in the petroleum industry. Relatively accurate three phase "partition" measurements can be made using nuclear, acoustic, electromagnetic and a combination of these technologies. As an example, the well known gamma ray attenuation technique can be used to measure an apparent bulk density of a two phase flow comprising liquid and gas. If the bulk density of each phase is known, the partition or fraction of volumes of liquid and gas can be computed from the measured bulk density. The problem lies, however, in determining accurately the linear flow velocities of each of these phases, which is required to convert the partition measurements into corresponding volumetric flow rates. Various relationships have been developed to calculate the relative or slippage velocity of two phases with respect to a measured third phase, but the calculations are replete with assumptions and arc only as accurate as the often dubious assumptions. In addition, these devices are usually quite complex both electronically and mechanically, are expensive to fabricate, and are very expensive to maintain and to calibrate.
Neutron sources (14 MeV) have been used to irradiate a composite fluid comprising a water component with neutrons thereby inducing .sup.16 N in the water phase by means of the .sup.16 O(n,p).sup.16 N reaction. This is usually referred to as an "oxygen activation" type measurement. Linear flow rate of the water phase and even the volumetric flow rate of the water phase can be determined, by measuring gamma radiation resulting from .sup.16 N, which is completely independent of the volumetric flow rates of any other non-oxygen phase of the composite stream. Since the half life of .sup.16 N is only approximately 6.2 seconds, long term contamination of the fluid does not present a problem. The method yields only flow parameters of the oxygen bearing phase. As an example, fluid produced from oil and gas wells usually comprises oil, water and gas. The neutron activation technique can be used to obtain volumetric flow rate of the water phase only. Since neither the gas or oil phases contain oxygen, no information is obtained concerning the flow of these phases.
To summarize the prior art in multi-phase flow measurements, especially as they pertain to the petroleum industry, no effective and direct techniques are available to measure two or three phase flow in a pipeline that do not exhibit limiting features discussed above. The test separator is capable of giving definitive answers to three phase flow measurements only if all of the various parameters of the previously mentioned three meters measuring the various flows are considered. Other limiting factors of test separator methodology include the dump rate for the liquids being 5 to 10 times the average flow rate, the entrained gas in both the water and the oil expanding as pressure is lowered going through the meter and over-registering the volume of liquids, liquids being carried through the gas meter by the higher velocity and insufficient demisting of this phase, and changes in liquid levels due to the slugging resulting from insufficient separation. These items are more often than not disregarded, thereby resulting in a large percentage of test separator testing on producing wells which overstates the volume ranging from a nominal 10% to values in excess of 100% when compared with sales volumes. As mentioned previously, the test separator technique requires massive, heavy, costly equipment, significant time for complete phase separation, and is certainly not applicable for real time, pipeline measurements where there are often sudden changes in the flow phase composition and flow regimes.
An object of the present invention is to provide multi-phase apparatus and methods to measure volumetric flow rate of one or more phases of a composite fluid, wherein no assumptions are needed concerning the linear flow velocities or the slippage velocities of the multiple phases.
Another aspect of the present invention is to provide a multi-phase flow measurement system for the petroleum industry, wherein volumetric flow rates of water, oil and possibly gas phases of produced fluids are measured directly, in real time, in a fluid stream flowing within a pipeline.
Still another object of the present invention is to provide accurate and precise measures of multiple phases of a fluid flow.
An additional benefit of the invention is to provide a multi-phase flow measurement system which is based upon the measure of radioactive levels, wherein the measuring equipment is extremely accurate and precise thereby allowing the use of very small or "exempt" quantities of radioactive materials which present no human or environmental hazards.
Another value of the present invention is to provide multi-phase flow measurement apparatus which is reliable, inexpensive to manufacture, inexpensive to operate AND suitable for rugged field use.
Still another object of the invention is to provide suitable calibration apparatus and methods with which the multi-phase flow system can be calibrated, where the invention, properly calibrated, can also serve as a calibration device for other types of multi-phase meters and test separators.
There are other objects and applications of the invention that will become apparent in the following disclosure and appended claims.